1. Field of the Disclosure
The disclosure relates generally to methods and apparatus for drilling and completing well bores. More specifically, the disclosure relates to methods and apparatus for a permanent anchoring device in a packer assembly.
2. Background Art
In the drilling, completing, or reworking of oil wells, a great variety of downhole tools are used. Particularly, downhole tools, referred to as packers and bridge plugs, are designed to isolate certain areas in a wellbore, and are well known in the art of producing oil and gas. Packers and bridge plugs are similar in structure and similar in the method in which they are set in a casing, however, they are designed to perform different functions in a wellbore. A bridge plug may be set in a casing as a lower limit, whereas a packer may be set above the bridge plug as an upper limit forming an isolated zone between the two. It is then possible to pressure down through a bore of the packer to communicate with the isolated region.
Downhole packers are typically used to seal an annular area formed between two coaxially disposed tubulars within a wellbore. A packer may seal, for example, an annulus formed between production tubing disposed within wellbore casing. Alternatively, some packers seal an annulus between the outside of a tubular and an unlined borehole. Routine uses of packers include the protection of casing from pressure, both well and stimulation pressures, and protection of the wellbore casing from corrosive fluids. Other common uses may include the isolation of formations or of leaks within wellbore casing, squeezed perforation, or multiple producing zones of a well, thereby preventing migration of fluid or pressure between zones. Packers may also be used to hold kill fluids or treating fluids in the casing annulus.
A downhole packer assembly may be run into a wellbore with a smaller initial outside diameter that then expands externally to seal the wellbore. The two most common forms are the production or test packer and the inflatable packer. Packers employ flexible, elastomeric elements that expand. The expansion of the former may be accomplished by squeezing the elastomeric elements (somewhat doughnut shaped) between two plates, forcing the sides to bulge outward. The expansion of the latter is accomplished by pumping a fluid into a bladder, in much the same fashion as a balloon, but having more robust construction. Packers may be set in cased holes while inflatable packers may be used in open or cased holes. Installing the packer downhole involves running it on a wireline, pipe or coiled tubing. While, some packers may be designed to be removable, others are installed as permanent, and therefore not retrievable. Permanent packers must be drilled out and destroyed to be removed from a wellbore. The pieces of the packer are circulated back to the surface in the drilling fluid. As such, permanent packers are constructed of materials that are easy to drill or mill out.
Traditional packers include a sealing element having anti-extrusion rings on both upper and lower ends and a series of slips above and/or below the sealing element. Typically, a setting tool would be run with the packer to set the packer. The setting may be accomplished hydraulically due to relative movement created by the setting tool when subjected to applied pressure. This relative movement causes the slips to move up cones and extend into the surrounding tubular casing wall. At the same time, the sealing element may be compressed into sealing contact with the surrounding tubular casing wall. The set position of the packer may be held in place by a body lock ring, which may prevent reversal of the relative movement.
The terms “packer” and “bridge plug” may be used interchangeably when describing the structure and manner in which they are set in a casing. A significant difference in the functionality of the two is the ability to pressure down through a bore of a packer. For figures and descriptions within, references are made to packers only. FIG. 1 further illustrates the components of a typical packer assembly 100 as installed in a wellbore 104. A packer assembly 100 may be set in a well casing 102 lining a wellbore 104 drilled into an oil and gas producing formation 106. Packer 100 may be connected with a production tubing string 108 leading to a well head, not shown, at the surface end of the well for conducting produced fluids from the well bore 104 to the well head. Casing 102 may be perforated at 110 to allow well fluids, such as oil and gas, to flow from the formation through the casing into the wellbore. Packer 100 may be locked with the wall of casing 102 by upper slips 112 and lower slips 114. Packer 100 may include a seal 116 which is expanded against the wall of casing 102 by longitudinal compressive forces forming a fluid-tight seal around packer 100. Seal 116 ensures that the formation pressure is held in wellbore 104 below seal assembly 116 and formation fluids are forced through the bore of packer 100 to flow to the surface through production tubing 108.
In the past, various configurations of packer assemblies have been disclosed for use in downhole operations. U.S. Pat. No. 4,753,444 to Jackson et al. discloses a packer having a conventional sealing element located around the outside of a mandrel. Anti-extrusion rings and back-up rings contain the seal element ends and are compressed to radially expand the seal element outwardly into contact with the well casing. U.S. Pat. No. 4,852,649 to Young discloses packers having multiple moving packer elements which distribute stresses across the elements as the packer elements expand to seal the wellbore annulus. In U.S. Pat. No. 5,046,557 to Manderscheid, multiple seal elements are separated with spacers around the exterior surface of a mandrel. The seal elements are hydraulically set to contact the well casing.
Further, U.S. Pat. No. 3,526,277 to Scott discloses an anchoring means for well bore tools. Disclosed is an expander having oppositely facing conical surfaces which cooperate with a pair of spaced apart sets of slip elements that are independently outwardly movable into anchoring engagement with the well wall.
Still further, U.S. Pat. No. 4,526,229 to Dickerson discloses a hydraulic packer assembly for sealing an annulus between a well casing and a tubing string inserted within the well casing having a packer and a setting tool. The packer includes a packer body having an internal bore with a seal and gripping members mounted on its exterior surface for engaging the interior surface of the well casing.
An integral component to the functioning of a downhole packer assembly is the anchoring device which radially expands to engage the casing wall to prevent movement in the wellbore. U.S. Pat. No. 6,164,377, which is assigned to the assignee of the present disclosure, discloses a slip assembly for engaging a downhole tool and preventing it from rotating within a casing. The slip assembly comprises a frangible ring and a plurality of slip pads supported on the ring, the slip pads preferably engaging the downhole tool by a tongue and groove mechanism. In addition, the camming interfaces between each slip pad and the tool comprise planar surfaces.
In setting the packer assembly in the well casing, an axial force is imparted on a mechanism in the anchoring device to cause a frangible ring to break into a number of individual slip segments. The slip segments are forced out radially to engage the casing wall inner diameter. In the separation of the frangible ring into individual slip segments, and during the subsequent radial expansion, a random and uneven spacing of the slip segments often occurs around the circumference of the casing wall. The uneven spacing between slip segments creates a localized stress pattern that is closely associated with the random contact with the casing wall.
Additionally, the slip segments disclosed in prior art have a smaller radius of curvature than the casing in which they are set. This geometry causes a contact area between the slip segment and the casing wall to be concentrated at the center plane of each slip segment. The small contact radii of the slip segments creates a scallop effect that must distort the casing or break the slip in additional locations to gain contact area. This configuration may essentially “gouge” into the casing wall or break off corners of the slips in an effort to engage the casing wall. The metal deformation caused by the gouging may further create higher stress areas which may be detrimental to the integrity of the engagement between the packer assembly and the casing wall.
Accordingly, there exists a need for an anchoring device that forces the slips into the casing wall to distribute the load more uniformly when set in the casing, thereby mitigating excessive gouging of the casing or breaking off of teeth.